Accurate analyses of fluid flow, including distinguishing between single and multi-phase flow, evaluating flow properties, and determining fluid velocity profile and viscosity, are important in evaluating production efficiencies of oil and gas wells and optimizing that production process. Fluid in a hydrocarbon producing wellbore often exhibits multi-phase flow characteristics because gaseous and aqueous hydrocarbons may be produced from different zones. Often the fluid is a system of two immiscible fluids, e.g., hydrocarbon and water. The hydrocarbon may be present in a greater amount with the water distributed in a lesser amount, or vice versa. Multi-phase flow often exhibits two-phase flow patterns such as water-gas or oil-gas. Other flow patterns may exhibit three-phase (gas, liquid, and solid) or other emulsion and/or turbulent related multi-phase flow patterns. With detailed understanding of the flow, skilled persons can adjust process parameters to control production efficiency from different zones in a wellbore.
Existing flow measurement techniques are designed for single-phase volumetric or mass flow detection, but their measurement accuracy is greatly affected by potential multi-phase fluid properties related to flow field distribution and fluid velocity. This is critical because many fluids have different flow regimes, such as laminar or turbulent flow. Laminar flow occurs where viscous forces are dominant over inertial forces and is characterized by smooth, constant fluid motion. Turbulent flow is dominated by inertial forces which tend to produce chaotic eddies, vortices and other flow instabilities. The Reynolds number (Re) is a measure of the ratio of inertial forces to viscous forces and is high for turbulent flow and lower for laminar flow. For example, in the case of flow through a straight pipe with a circular cross-section, laminar flow typically occurs where Re<2040 and flow can be turbulent at Re>2040. In extreme cases Re<<1 and fluid flow is highly viscous. Such viscous fluid flow often is referred to as Stokes flow. Existing flowmeters cannot account for different flow regimes within a fluid.
Moreover, multi-phase fluids exhibit flow field distributions and velocity profiles even more complex than those of single-phase fluids. Examples of multi-phase flow patterns include bubbly flow, slug flow, churn flow, annular flow, and combinations thereof. For single phase fluid flow, the best accuracy in measuring volumetric flowrate is about 3-5 percent. For multi-phase fluid flow that accuracy is degraded even to 20-25 percent. Under downhole harsh conditions of T>100° C. and P>10 kpsi, the hydrocarbon fluid phase is more or less described by equation of state (EoS). Whether a hydrocarbon fluid is in a liquid phase or in a gas phase depends upon the pressure and temperature, and in a specific case, liquid and gas phases may co-exist when the pressure is lower than its bubble point or dew point.
Despite advancements in fluid flow detection techniques (such as ultrasonic, magnetic, optic, mechanical, etc.), flowrate detection in mixed phases, especially immiscible fluids, still represents a great challenge. It often happens that apparent, erratic volumetric detections are attributed to low flowmeter accuracy, but careful study reveals that these flowmeters actually give volumetric flowrate without considering the complicated nature of the multi-phase fluid flow formation that can vary among laminar, turbulent, and Stokes flow. If this multi-phase behavior is not considered, determining the fluid type and actual flow rate can be difficult. It is thus an object of the present disclosure to provide devices, systems, and methods for accurate multiphase fluid flow profile measurement.
The figures referred to above are not drawn necessarily to scale and should be understood to present representations of embodiments and illustrations of the principles involved.